Ormat Technologies Inc (ORA) 2013 Q4 法說會逐字稿

Welcome to the Ormat Q4 year-end 2013 conference call. All lines have been placed on listen-only mode and the floor will be open for your questions and comments following the presentation. Without further ado it is my pleasure to turn the floor over to your host, Mr. Rob Fink. Mr. Fink, the floor is yours.

Thank you, West, and thank you, everyone, for joining us today. Hosting the call from Ormat are Dita Bronicki, Chief Executive Officer; Yoram Bronicki, President and Chief Operating Officer; Doron Blachar, Chief Financial Officer; and Smadar Lavi, Vice President of Corporate Finance and Investor Relations.

Before beginning we would like to remind you that the information provided during this call may contain forward-looking statements relating to current expectations, estimates, forecasts and projections about future events that are forward-looking as defined in the Private Securities Litigation Reform Act of 1995.

Before beginning we would like to remind you that the information provided during this call may contain forward-looking statements relating to current expectations, estimates, forecasts and projections about future events that are forward-looking as defined in the Private Securities Litigation Reform Act of 1995.

These forward-looking statements generally relate to the Company's plans, objectives and expectations for future operations and are based on management's current estimates, projections, future results or trends. Actual future results may differ materially from those projected as a result of certain risks and uncertainties. For a discussion of such risks and uncertainties, please visit Risk Factors as described in Ormat Technologies' annual report on Form 10-K filed with the SEC on March 11, 2013.

In addition, during the call we will present non-GAAP financial measures such as EBITDA and adjusted EBITDA. Reconciliations to the most directly compared GAAP measures and management reasons for presenting such information is set forth in the press release that was issued last night as well as in the slide posted on our website, Ormat.com. Because these measures are not calculated in accordance with US GAAP they should not be considered in isolation from our financial statement prepared in accordance with GAAP.

Before I turn the call over to management I would like to remind everyone that a slide presentation accompanying this call may be accessed on the Company's website, Ormat.com, under the IR Events and Presentations link that is found in the Investor Relations tab. With all that said I would now like to turn the call over to Dita. Dita, the call is yours.

Thank you, Rob, and good morning, everyone. Thank you for joining us today for the presentation of our fourth-quarter and full-year 2013 results and outlook for the near future.

Slide 4 presents the highlights for the year. Doron will go into the numbers in detail in a minute. I would like to provide an overview of what has been an exciting and productive year from a business and operational point of view.

During 2013 we successfully completed nine power plants with approximately 270 megawatts of gross generating capacity. The plants, which we completed for our customers and for our own portfolio, significantly contributed to the growth of the geothermal industry. These accomplishments drove our performance in both our product and electricity segments and resulted in record revenue and adjusted EBITDA.

We successfully reduced our exposure to natural gas prices by securing three fixed price long-term PPAs in California and continued our business development efforts to expand our operations globally. Our achievements reflect Ormat's expertise in developing and managing projects that will deliver strong earnings growth and drive value to shareholders.

Our success in recent years in answering the demand for electricity with a geothermal product that is both competitive and rates and superior in its attributes to most of our other alternatives is a testament to the important role that geothermal has in addressing the energy needs of the countries that have such a resource. By providing us with the comfort that the demand for this energy will remain strong across the globe and allow us to benefit from our position in this market.

With that said, I would like to turn the call over to Doron to review the financial results. Yoram will then provide a review of our operations and I will return for closing remarks before opening the call for Q&A. Doron.

Thank you, Dita, and good morning, everyone. Let me start by providing an overview of our financial results for the year ended December 31, 2013. Starting with slide 6, total revenues for 2013 were $533.2 million, a 6.3% increase over revenues of $501 million in 2012.

In our electricity segment, as you can see on slide 7, revenue grew 4.7% to $329.7 million in 2013 from $314.9 million in 2012. The increase was primarily due to the new capacity coming online.

In line with our policy since 2012, we continue to take actions to mitigate the impact of natural gas prices on our electricity segment through our hedging activities. For 2014 we entered into a derivative transaction at a fixed average price of $4.07 per MMBtu.

It is important to note that the hedging transactions that we do eliminate the economic impact of changes to prices of natural gas in specific months. If we lose on the hedge contract we are compensated from the revenues that we get from the electricity segment and vice versa. Both parts are recorded in the electricity revenue.

However, due to the accounting guidelines we are required to mark-to-market our forward hedge and this brings volatility into the reported period. When we internally analyze our results we exclude the impact of the mark-to-market.

Let me demonstrate the impact of the mark-to-market adjustment on the 2013 annual revenue. As a result of our hedging transaction that we entered in 2013 for 2014, we recorded a $2.8 million loss in mark-to-market adjustments in 2013 compared with a $2.3 million mark-to-market gain related to the transaction we entered in 2012 for 2013 that were recorded in (technical difficulty). Excluding these mark-to-market adjustments electricity revenue increased 6.4% year over year.

In the product segment on slide 8, product revenue rose 8.9% year over year to a record of $203.5 million. The increase reflects the growth in new customer orders that we secured in 2012 and 2013.

Moving to slide 9, the Company's combined gross margin for 2013 was 30% compared to 25.7% in 2012. In the product segment gross margin for 2013 was $62.9 million or 30.9% compared to $51.5 million or 27.6% in 2012.

The increase in the product gross margin is mainly attributable to the different product mix and margin in the various sales contracts. The gross margin for 2013 is higher than the typical level for this segment and we do not expect gross margin to remain at such a level in 2014.

In the electricity segment gross margin for 2013 was $96.9 million or 29.4% compared to $77.5 million or 24.6% in 2012. The increase in the electricity gross margin is mainly due to the higher margin the new power plants contribute to our fleet performance.

Moving to slide 10, operating income in 2013 was $97 million compared to an operating loss of $159.9 million in the same period last year. The 2012 results included a non-cash impairment charge of $236.4 million taken at the North Brawley (inaudible) Geothermal Plant. If we exclude it from the result operating income grew from $76.5 million to $97 million which represents a 26.8% increase.

Operating income attributable to our electricity segment in 2013 was $54.3 million compared to an operating loss of $190 million in 2012. Excluding the impairment charge the operating income increased 17% from $46.4 million to $54.3 million. Operating income attributable to our product segment increased 41.9% from -- to $42.7 million in 2013.

Moving to slide 11, interest expense net of capitalized interest for 2013 was $73.8 million compared to $64.1 million in 2012. The $9.7 million rise is mainly attributable to an increase of $6.9 million in interest expense related to the sale of tax benefits and a $4.4 million decrease related to interest capitalized to projects.

Moving to slide 12, net income attributable to the Company's stockholders for 2013 was $41.2 million or $0.91 per share compared to a net loss of $213 million or $4.69 per share in 2012. The increase was primarily related to the non-cash impairment charge that I mentioned before.

Now I would like to go over a few quarterly financial highlights beginning with slide 13. For the fourth quarter of 2013 total revenue was $130.9 million compared to $113.3 million in the fourth quarter of 2012. Revenues in the electricity segment increased 11.4% to $84.7 million, up from $76.1 million in the fourth quarter of 2012. Revenues in the product segments were $46.2 million, an increase of 23.9% compared to $37.3 million in the fourth quarter of 2012.

Now on slide 14, operating income in the fourth quarter 2013 was $21.6 million compared to an operating loss of $220.9 million last year. Net income attributable to the Company's stockholders for the fourth quarter was $8.2 million or $0.18 per share compared to a net loss of $229 million or $5.04 per share diluted in the fourth quarter of 2012.

As shown on slide 15, adjusted EBITDA for 2013 was $227.1 million compared to $185.7 million in the same period last year, which represents a 22.3% increase. Adjusted EBITDA for the fourth quarter of 2013 was $51.4 million compared to $35.2 million in the same quarter last year which represents a 45.8% increase.

Net cash provided by operating activities was $54.5 million for the fourth quarter of 2013 compared to $27.1 million in the fourth quarter of 2012. Net cash provided by operating activities were $86.8 million in 2013 compared to $89.5 million in 2012.

Moving to slide 16, cash, cash equivalents as of December 31, 2013 were $57.4 million. The accompanying slide breaks down the use of cash during the past year.

Our long-term debt as of December 31, 2013 and the payment schedules are presented on slide 17 of the presentation. The average cost of this for the Company stands at 6.1%.

On February 25, 2014, Ormat's Board of Directors approved a payment of the quarterly dividend of $0.06 per share which is an addition to the payment of $0.08 per share paid in 2013. The dividend will be paid on March 27, 2014 to shareholders of record as of closing of business day on March 13, 2014.

The dividend payment was resumed in Q2 2013 after satisfying the claw back provision resulted from 2012 dividend payment in compliance with the requirements of the covenants in our financing document. We expect to pay a quarterly dividend of $0.05 per share for the first three quarters of 2014.

That concludes my financial overview. I would like now to turn the call to Yoram for an operational update. Yoram.

Thank you, Doran, and good morning, everyone. Starting with slide 19, 2013 was a very successful year for the operational development teams of Ormat.

In our O&M portfolio we completed three new power plants, Olkaria plant II and III, Don A. Campbell plant and the refurbishment of Mammoth G1, all moved from end of construction to electricity sales at full power in less than a month and all metrics ceded their contractual generation targets.

The plants and Kenya and the US added 70 megawatt net of new capacity. At McGinness Hills the success of the resource development and the equipment design allowed us to increase the declared capacity to 38 megawatt. The well field and power plant enhancement work we conducted in Jersey Valley brought the plant to its design generating capacity.

From a business standpoint we amended the PPA at McGinness Hills allowing us to develop a second phase. We amended the PPA at Zunil in Guatemala and replaced SO#4 contracts with fixed-price contracts for Mammoth G1, G3 and signed a new PPA for Heber 1 which will become effective in December 2015 and will affect the electricity revenues from 2016 onward.

We also completed the acquisition of Platanares in Honduras allowing us to release Phase 1 for drilling activity. We completed most of the work on the 10 megawatt Heber solar project, but are still waiting for the interconnection facilities to be completed. However, we are considering the option of selling the project prior to completion.

Moving to slide 20, the total generation for 2013 was approximately 4.3 million megawatt hours, which is an increase of 7.9% from last year. The growth in generation is mainly due to the contribution from Olkaria III plant 2, McGinness Hills, Tuscarora and Jersey Valley. Continuous improvements in our power plants have allowed us to reduce our operating expenses, excluding depreciation, from $37 a megawatt hour to $36.

For an update on our current generation capacity please turn to slide 21. We made a few changes, as you can see, in the table. The generating capacity of Brady and Steamboat complexes have been reduced to reflect the changes in the resource conditions, the performance of McGinness Hills and Olkaria has been very strong and we've updated their capacity to reflect this.

Moving to slide 22, in 2014 we plan to invest approximately $150 million in new projects in development and construction. The main elements of this investment plant are the second phase of McGinness Hills in Nevada and the Platanares project in Honduras. The Menangai project in Kenya as well as additional projects in the US and in the rest of the world that are currently under exploration where we expect them to start the development process during the year.

As stated previously, the readiness for continued construction and expected economics will determine the release of each project. At McGinness Hills Phase 2 field development is underway to support the 30 megawatt project which is expected to be completed in mid-2015. In Platanares we plan to begin phase development at the project and start drilling wells early in 2014. The first 18 megawatt phase is expected to be completed in 2016.

The Menangai project in Kenya is an energy conversion agreement whereby GDC, the Kenyan government entity responsible for the development of the new geothermal resources in Kenya, will develop the geothermal field and will convert the resource -- I'm sorry, we will convert the resource to electricity and sell the power to KPLC while paying GDC a resource fee. The joint venture of Ormat into additional parties and would Ormat will own 51% was awarded a 30 to 35 megawatt project and we are currently negotiating the product agreements.

In Sarulla the consortium has started preliminary testing and development activities at the site and some basic infrastructure work. The three major contracts have been signed -- the supply contracts for the Ormat equipment; a drilling contract with a third party; and an EPC with a third-party. Financing for the project is progressing well and expected to be signed in the first half of 2014.

To summarize our budget includes new projects and late stage development projects that we will contribute to our organic growth. The projects that we anticipate working on this year may add between 120 and 150 megawatts in the years 2015 to 2017.

However, for all of this to materialize we will need to be successful in the development work and invest additional capital beyond 2014. Besides the investment in organic growth, some of the investment that is planned for the existing plants could lead to additional growth.

In addition, we will continue to look for acquisition opportunities in the US and globally. We expect that the continuous nature of our project development activity will allow a number of the US projects that are in our capital plan to benefit from the extension of the PTC in the coming years.

We have 38 prospects in early exploration or where activity has yet to begin in the US, Chile, Guatemala, New Zealand and Indonesia. In addition to adding capacity we will continue to seek technical and commercial opportunities to improve existing plants. Examples are the PPA restructuring of the Standard Offer Number 4 contracts at Mammoth and Heber and the recent amendment to the Zunil PPA.

Besides a 15-year extension in Zunil, the amendment, which gives us the right to operate Zunil well field, will allow us to increase the revenue from the plant mostly through enhancement of the aging geothermal field.

Slide 23 provides for an update on the product segment. As Dita stated, we had an outstanding performance in the product segment in 2013. The strong order flow resulted in a record revenue of $203.5 million, but we are equally proud of our ability to provide our customers with our best-in-class solutions.

To recap some of our achievements, one is a successful completion of the world's largest single site binary geothermal power plant, the Ngatamariki plant in New Zealand. The successful collaboration with Enel Green Power North America at the Cove Fort geothermal power plant project in Utah. The Norske Skog plant in New Zealand and the successful repowering of Cyrq's Thermo I plant in Utah.

The projects that we provided our customers with were very diverse in terms of operating conditions and owner specification ranging from low to high [FLP], from simple grade integration to ones where the system operator has the most stringent demands and from operators who prefer simplicity to those who require the ability to operate in [island] mode.

To the best of our knowledge we were able to cater to our customers' needs fully and all of them were able to meet or exceed their contractual commitments.

Most of the projects that we completed in 2013 were also executed rapidly. And in several instances we were able to increase the design generation capacity. In the process we not only helped our customers but helped to bolster the image of our industry with a viable and credible projects that will generate clean power for many years to come.

We continue to see strong drivers that we believe may further strengthen our backlog which we currently stand at $165 million excluding the $254 million Sarulla supply contract. Let me turn the call over to Dita.

Thank you, Yoram. Starting with slide 25, looking at the global NLG landscape, we continue to see countries around the world recognizing the benefits of using geothermal to meet their growing demand. Multinational organizations and nongovernmental organizations are continuing to offer incentives to lower the cost of capital as these various entities look to increase their reliance on (inaudible) energy.

In the United States interest in geothermal energy remains strong for numerous reasons including legislative support of renewable portfolio standards calling nuclear base load energy retirement and increasing awareness of the positive value of geothermal characteristics as compared to intermittent renewable technology. We believe the encouraging environment will continue to do drive growth in both segments.

As we discussed on previous earning calls, we have been evaluating along with our Board of Directors the viability of adopting (inaudible). We have determined that based on our portfolio size and its expansion pace, as well as the cost of having another public company utilizing a public (inaudible) is not a viable solution at this time. We examined other vehicles such as asset realization or private equity transactions as a way to generate additional shareholder value.

If you could please turn to slide 26 you will see our CapEx requirement for 2014. We plan to invest a total of $130 million in capital expenditures on new projects under construction and enhancement. In addition, $99 million is budgeted for development exploration activity maintenance capital for operating projects and investments in machinery and equipment as well as an $80.4 million for debt repayment.

The funding of this program will come from cash on hand at the end of 2013, unused corporate lines of credit, expected cash from operations, expected ITC cash grant for Campbell and from an expected financing of McGinness Hills space to which is covered under the existing financing structure of OFC 2 senior secured notes.

Turning to slide 27, we outline our revenue outlook for 2014. For the full year 2014 we expect electricity segment revenues to be between $370 million and $380 million. And the product segment revenue to be between $170 million and $180 million.

The product segment guidance includes $36 million from the Sarulla projects that are subject to financial close. Based on our current projection we anticipate that the product segment revenues in the second quarter will be weaker compared to the other quarters due to the expected timing of when we will recognize the revenue.

Let me add a few words on the recent decision to hire Mr. Isaac Angel as the next CEO of Ormat. Mr. Angel will join Ormat on April 1 and begin the process of transitioning into the role of CEO effective July 1, 2014. Our decision was made following a methodical sales process for a candidate who could meet as closely as possible the profile that was defined for a CEO of our Company.

We are confident that Isaac is the right choice. His proven track record of building a growing technology company, his previous experience running a public Company and his understanding of capital markets makes him a well-suited candidate to lead the Company to higher levels of performance in the coming years.

Isaac is a quick learner and we are confident that with the continued support of Yoram as an active Chairman, myself at the Board level in our experienced management team he will very quickly learn the specifics of the geothermal industry. In the coming months you will of course have opportunity to meet him personally.

As this is my last year-end earnings call let me share with you a short summary of almost 10 years since our IPO. We have more than doubled our operating portfolio from 300 megawatt to 626 megawatts. Our revenues and adjusted EBITDA also doubled and our market cap increased 2.5 times from $480 million to $1.2 billion.

We deepened our vertical integration by creating a (inaudible) Company and more importantly we have substantially improved the way we explore new resources, reduce the cost of early exploration and increase the number of prospects for future development.

The lessons learned on greenfield development have driven a notable improvement in our operational performance. During 2012 and 2013 all of our projects brought online were on time, on budget and at or above the design performance level. On the technology side we increased our turbine size and efficiencies allowing for cost-effective power generation in our plants and for our customers.

Overall we have strengthened our position as a leader in the geothermal development arena. I am proud to pass the baton knowing that the Company and its devoted employees and management are ready to reach new heights. With that I would like to thank you for your support and at this time I would like to open the call for questions. Operator.

(Operator Instructions). Mark Barnett.

Let me start, Dita, by saying congratulations and well deserved break for you. I have a couple of questions about some of the items you mentioned in the slides today. And the first would be are you still on schedule for completing the Heber work at the end of midyear this year?

Yes.

Okay. And you mentioned when the Platanares Project either before -- I missed your full sentence, but you mentioned that you might be motivated to sell that before it is fully brought online. Is there anything in particular that is motivating that?

This is was Heber solar and not Platanares.

Oh, my bad. Okay. So then could you also maybe talk about the circumstances around your desire to sell that project?

I think that we are looking at what would provide the best return from that investment. And given the fact that it is non-core for us, the solar part, we may actually have a better way to realize value from that by selling the project. If not we can certainly run it.

Okay. And then just one more question on California. The last Analyst Day you had walked through some potential changes in California's renewable compensation that particularly would benefit geothermal. I mean outside of SO#4 contracts that you have renegotiated, is there anything in particular that we should be watching for on this front for your projects in that state?

I think that if you look at California, and this is certainly beyond Ormat, but if you look at California, the broader aspects of California's renewable energy policy you see that there is growing concern about the cost of integration of the intermittent power whether it is wind or solar.

And there are more thoughts about providing, if you would like, a premium to geothermal power that is part of the solution and not part of the intermittency problem. And of course this is far beyond Ormat, we are following the process and we provide -- and we intervene in the process where we can. But the decision is of course beyond us.

But I think that as we look into the RPS compliance period 3, I think that there are reasons to believe that geothermal will get preferential treatment because it should. Solar is much more expensive to the state as a state than just the cost of putting it online at the plant's gate, so to speak.

Understood. Okay. Well thanks for your comments and again, congratulations, Dita.

Thank you.

(Operator Instructions). Dan Mannes.

Nice quarter. And obviously my congratulations again to Dita. I do have a couple quick follow-up questions here. First of all as it relates to your development pipeline, you talked about a potential for 120 to 150 megawatts. You kind of call out about 77 megawatts worth.

I guess my question is for the difference between the two, the projects that you are working on that you haven't specifically named, given the timeline between 2015 and 2017 and knowing how long permitting is and PPA windows, I guess I am just trying to figure out how advanced those projects are for them to be able to make that window and be online and that timeframe?

So I think the sort of I will give you an indirect answer. They are quite advanced when it comes to development, but they are not at the point that we are comfortable releasing more details about them. So clearly we have done resource work. Clearly we have done permitting work, site acquisition, work on transmission, all of this.

And this is why we are fairly comfortable that there is a substantial horizon beyond the projects that were named. But none of those were released and typically our practice is to release that information once the PPA is signed. That is -- that has been our past practice and we will probably adhere to that.

Okay. And conceivably could any of these be projects which you had already worked on for a while and then maybe put on the shelf? I am thinking something like the Mammoth expansion -- or sorry, the CD4 expansion or something like that.

I think that you make a very compelling argument (laughter).

Fair enough. Building on the discussion on California, you mentioned the next phase of the RPS. I guess I was wondering given what we are seeing now just currently given volatile natural gas prices, the shutdown of San Onofre, the drought conditions impacting Hydro.

Is that helping you at all as you think about maybe the existing SRAC contracts and maybe being able to recontract those? Has there been any movement there or is that still kind of -- is that still in a bit of a lull?

So this is what I will say as pure speculation on my part. So all the Safe Harbor has to be doubled on that. But I would say that clearly -- I mean the interesting part about regulation is how large the inertia is. And sometimes the writing is on the wall, but it takes a lot of time for everybody to realize what the writing says or how it relates to this.

And so, I think that many people said that natural gas, the low natural gas prices were not necessarily something that could stay. Nobody knows what natural gas prices would be. But I think that as we see just the volatility in this quarter and the very high prices of natural gas I think would -- should provide some reason for some off takers to try and hedge their expenses.

Really with California moving more and more towards gas with shutting down of coal plants and of course the nuclear plants. And I think that there should be some regulators and some utilities that would say, well, what happened between 2006 and 2008 with high natural gas prices was not a one-off incident in here we saw it again in the beginning of 2014.

So it makes a lot of sense to sign a contract -- PPA with a geothermal operator that provides the same quality of power if not better than a natural gas plant at the fixed-rate. So I think all of these things would provide a movement. Would we be able to use it to our advantage? I think that it is very likely. When? I don't know.

So it is really a very high-level statement. I think that this is -- these are important evidence in clarifying that natural gas burning power plants are maybe cleaner than other alternatives, but it is not necessarily -- it is not as cheap as people would say based on 2012 gas prices. And I think that this could be good for us.

Got it. One if you will indulge me one more on the product side. You talk about margins maybe normalizing a bit. But I look over the last -- I think since 2008 you've been consistently at 28% and higher on an annual basis. And that is with a changing mix of business some years more EPC, some years more product.

And that is also an environment where we are seeing competition lifting up a bit, you are seeing -- so I guess I'm trying to understand have you guys gotten maybe more efficient on the productivity side? Has something changed in the business because it doesn't like you sustained a much higher margin level for a couple of years now even though you keep kind of telling us it is not going to stay here.

What I can say on the productivity side is that certainly we were -- we got better with experience and, although we are a very experienced Company, we get more experience every year. So sometimes when it relates to a lower margin at the end of the project because of our mistakes I think that we have learned from situations like this.

Certainly we were fortunate not to see the huge spike in commodity prices that was seen between 2006 and 2008 that makes it very hard whether it was on our internal projects or an external project it makes it very hard on the constructors side, it makes it very hard to do that. So I think that we certainly got better in some areas. Dita, I don't know if you want to add anything?

And just we have to add to it the volume, the fact that we add such a high volume of production in 2013 contributed to the higher margin even though maybe that each specific project didn't have on its own a higher margin. But to summarize the high-volume -- a specific mix of product, that is the most important element and some learning -- some efficiency or management efficiency are contributors to it.

Got it. Thank you very much.

(Operator Instructions). Gregg Orrill.

Just on the -- you didn't touch on the Puna contracting, maybe you could give us an update there, kind of what is baked in and the hedge profile?

What is specifically -- what question specifically do you have on the Puna contracting?

How hedged are you in 2014 and 2015 and what is the commodity price that is related there?

On 2014 we are fully hedged on the oil we have a forward contract that fully hedges us and pricing that is a little bit higher than 2013. 2015 is a little bit further down the road so we haven't hedged yet 2015. But we are monitoring (inaudible) the pricing and if we do find a good opportunity to hedge and 2015 either for Puna or for the natural gas prices than we might take advantage of this opportunity.

Thanks for the update.

JinMing Liu.

First thanks, Dita, for all of your hard work these years.

Thanks.

No problem. So my first I just want to follow-up with the previous question. What exactly are your hedging positions right now for both natural gas and the crude oil you are hedging?

For the natural gas we are hedged for the entire 2014 based on $4.07 and MMBtu as compared to 2013 we hedge at $4. Actually as we recognize revenue on a month-by-month the revenue that we recognize either through the hedge or through the actual number is stated at $4.07. And on the oil numbers we are hedged at $125, which is a bit higher than -- also a bit higher than 2013 for the entire year.

Okay. Thanks for the clarification. Regarding your Sarulla project, you didn't put that into your backlog in your guidance for the whole year. You put $36 million of revenue in there. So Just want to clarify, are you very confident that the project will go forward this year?

To the extent that any projection is confident the answer is, yes. The financing for the solar project is progressing very well and I think we are at the final stages of implementation. This of course doesn't mean that we will not have [crisis yet] before we get to closing. But we are confident that Sarulla will get to closing in the first half of 2014.

Okay, got it.

And as a result of it we are confident that a portion of the revenue will be recognized this year.

Okay. Okay, got that. Thanks a lot.

(Operator Instructions). Ella Fried.

I also would like to congratulate Dita and thank her for her very hard and productive work. I only have one question left, and it is regarding the debt level that we should expect in the end of 2014 before the new (inaudible) are coming online. Should we expect to an increase in the current level of debt especially if possible so of Heber solar doesn't come out?

If you would refer to the slide of the sources and uses --.

I'm sorry I mean net debt, I meant net debt.

Well, I think we have provided guidance for the numbers. We are going to pay off $84 million of debt during the year; we are planning to add McGinness Hills 2 into the OFC 2 financing. I think those are the main elements.

So it seems that the level is expected to be somewhat higher than presently before the new megawatts are coming online, am I right or --?

I made somewhat higher. If we are generating on average, I don't know, $100 million or $120 million of cash from operations per year and if we are planning to invest this year about $205 million in CapEx, then there is going to be some increase in debt, but not a substantial increase.

Okay, thank you very much. And thank you again for your contribution to the Company.

Thank you.

Dan Mannes.

I had one follow up. I wanted to ask you did take a write-down on some unsuccessful drilling in the quarter. Could you comment, number one, on either what project or what area that is? And number two, how you embed that or don't into your adjusted EBITDA?

It's one project in Utah and one project in Oregon; I don't think we have spoken too much about these project that were -- because it was done in an early stage and it is one of the things that we pride ourselves that we are now able to invest less in the project until we can determine if it is a go or a no go. It was not taken out in adjusted EBITDA, we can think about it.

Because I was going to ask about that. Normally if you are going to do an adjusted EBITDA number you kind of exclude some of those nonrecurring issues and obviously it was embedded into your CapEx and prior periods. But just wanted to make sure that was clear. Thank you.

(Operator Instructions). At this time there are no further questions.

Thank you all for listening and we look forward to meet you again in May.

Thank you. This concludes today's teleconference, we appreciate your participation. You may now disconnect your lines at this time.